The present invention relates to a method of enhancing recovery of petroleum from an oil bearing formation. In particular, the invention relates to the use of non-ionic surfactants in an enhanced oil recovery operation for the recovery of light oils from carbonate formations.
In the recovery of light oils (i.e., greater than 20.degree. API) from reservoirs, the use of primary production techniques (i.e., use of only the initial formation energy to recover the crude oil), followed by the secondary technique of waterflooding, recovers only about 60 to 70% of the original oil present in the formation.
Moreover, the use of certain enhanced oil recovery (EOR) techniques is also known within the art. These techniques can be generally classified as either a thermally based recovery methods, i.e., utilizing steam, or a gas-drive method that can be operated under either miscible or non-miscible conditions.
The gases which are commonly employed in gas-drive methods are those normally referred to as non-condensible gases, for example, nitrogen, carbon dioxide, methane, mixtures of methane with ethane, propane, butane, and higher hydrocarbon homologues. This class of gases include both natural gas and produced gas. Moreover, these include both "lean" gases, e.g., methane alone, or "rich" gases, e.g., methane mixed with ethane or the like.
For a given crude oil and temperature, the non-condensible gases become miscible with the oil above a pressure known as the minimum miscibility pressure. Above this pressure, these "non-condensible" gases attain a supercritical state wherein their behavior has characteristics of both gases and liquids.
With those enhanced recovery processes which employ non-condensible gases under miscible conditions, the oil can be caused to flow toward a producing well because the non-condensible gas "swells" the oil (i.e., increases the volume by dissolving in the oil) and, thus, reduces the viscosity of the oil.
The method of the present invention is preferably directed to this miscible operation although it is equally effective under non-miscible conditions.
A typical procedure involves injecting a slug of CO.sub.2 followed by the injection of a higher viscosity fluid such as water to "push" the CO.sub.2. See, for example, the discussion in U.S. Pat. No. 2,623,596. Moreover, U.S. Pat. No. 3,065,790 indicates that this process may be more cost effectively employed if a relatively small slug of CO.sub.2 is injected ahead of a drive fluid. In fact, as illustrated by U.S. Pat. No. 3,529,668, this type of recovery procedure is typically performed in "water alternating gas (WAG)" cycles.
Because of the viscosity and density differences between the CO.sub.2 and the oil (i.e., CO.sub.2 has only 5 to 10% of the viscosity of, e.g., light oil), the CO.sub.2 tends to bypass much of the oil when flowing through the pores of the rock reservoir.
One proposed solution to this problem associated with the bypassing of the CO.sub.2 has been through the use of a small amount of water which contains a surfactant, with the CO.sub.2. In particular, a surfactant has been proposed as a means for generating a foam or an emulsion in the formation. See, for example, U.S. Pat. No. 4,380,266 to Wellington and U.S. Pat. No. 5,502,538 to Wellington et al. Each of these foams or emulsions is composed of a non-condensible gas, such as CO.sub.2, and water which contains a surfactant.
The purpose of this foam is to inhibit the flow of the CO.sub.2 into that portion of the formation containing only residual oil saturation. In addition, the foam physically blocks the volumes through which CO.sub.2 is short-cutting. This forces the CO.sub.2 to drive the recoverable hydrocarbons from the less depleted portions of the reservoir toward the production well.
However, a number of problems have been encountered in attempting to provide an economical process. First of all, as clearly discussed within U.S. Pat. No. 4,380,266, the use of traditional surfactants, such as ethoxy-sulfates (particularly Alipal CD 128 supplied by GAF Corp.), suffers from problems associated with the instability of the foam produced in this environment. In the Society of Petroleum Engineers paper SPE 14394 (Las Vegas, Nev., Sep. 22-25, 1985), Borchardt, et. al. summarize evaluation of over 40 surfactants for use in CO.sub.2 foam flooding. Thus, while certain surfactants have been suggested for use in this manner, the art has been largely unable to provide a stable foam in this environment.
In particular, when using a non-condensible gas under miscible conditions, the creation of an effective foam is very difficult because either the salt concentration of the water in the formation (connate or injected brine), the residual oil in the reservoir, or the chemical instability of surfactants tends to break the foam or even prevent the foam from forming.
Another problem with the use of non-condensible gases such as CO.sub.2 is the undesirable and uneconomically high adsorption of surfactant onto formation rock. This is a particular problem with respect to systems which employ non-condensible gases such as CO.sub.2 when compared to steam drive methods, due to the fact that adsorption occurs at much lower levels in the higher temperature environment associated with steam as compared to the relatively low temperatures normally encountered in many light oil reservoirs amenable to miscible gas flooding. In other words, adsorption increases as the temperature is lowered.
Further in this regard, the art has employed anionic surfactants as foaming agents within enhanced recovery techniques such as CO.sub.2 flooding of oil formations made of sandstone and/or silica. Because the sandstone has a negative charge, the anionic surfactants are not appreciably adsorbed in the surrounding formation.
However, within a carbonate environment, which comprises primarily carbonate rock having a positive charge, the above described adsorption is effectively reversed. Thus, anionic surfactants are subject to uneconomically high adsorption losses to the formation rock (i.e. greater than about 0.5 mg/g of rock). Accordingly, anionic surfactants are not economically employable within this environment.
Alternative surfactants have failed to provide an economic solution to the above problem. For example, amphoteric surfactants, i.e., those surfactants which include both a positive and negative charge in the molecule, also suffer from high adsorption losses and thus they too are not economically feasible.
Furthermore, non-ionic surfactants, which do not suffer from the above adsorption problems associated with anionic surfactants, have been repeatedly dismissed by the art due to their "low foaming" reputation.
The hydrophilic-lipophilic balance (HLB) value is a measure of a surfactants ability to make oil-water emulsions. A non-ionic surfactant having a low HLB value (i.e., less than about 10) is considered oil soluble while a high HLB value (i.e., greater than about 13) are associated with water soluble surfactants. The non-ionic surfactants predominantly employed in car washes, dishwashers, and the like, have an HLB value of preferably about 13-15, most preferably about 13.
However, the need still exists for a surfactant which provides a stable foam and which can be economically employed in carbonate environments.
Accordingly, it is an object of the present invention to provide a foam-forming composition containing a non-ionic surfactant which does not exceedingly adsorb on the surrounding carbonate rock and which provides a stable foam during miscible gas flooding of the formation.
This and further objects will become apparent from the specification and claims which follow.